This report evaluates the potential of long duration energy storage to improve the reliability and sustainability of Prince Edward Island’s electricity system. Using detailed power system modelling and region-specific assumptions, it examines if storage can boost renewable utilization, reduce import alliance, and lower emissions, supporting the province’s clean energy transition and 2040 net-zero goal.

Background & Motivation

Prince Edward Island’s grid, already hosting 204 MW of wind and 30 MW of solar, faces challenges from seasonal variability, limited interconnections, and peak winter demand exceeding 300 MW. These factors leave Prince Edward Island heavily reliant on imports from New Brunswick, with diesel generation providing additional backup when required. Long duration energy storage, defined as systems capable of discharging for 10+ hours, can store surplus renewable energy and release it during low-generation or high-demand periods, improving utilization, reliability, and emissions performance. While mechanical options like pumped storage and chemical options like hydrogen storage are unfeasible in Prince Edward Island, electrochemical (battery) and thermal storage shows potential, especially as costs fall and federal incentives become available. This study assesses the potential role of long duration energy storage in supporting the island’s 2040 net-zero target and improving the electricity grid.

Methodology

The study applied a four-step approach:

Part I: LDES Technology Screening and Evaluation

Six candidate technologies were assessed for technical feasibility, cost-effectiveness, and alignment with Prince Edward Island’s geography, excluding those physically unsuitable for long duration energy storage on the island.

Part II: Grid Characterization

Various factors corresponding to the island’s grid were analyzed such as regional demand, renewable resource potential, and transmission infrastructure to determine optimal siting and integration opportunities for long duration energy storage.

Part III: Power System Modelling with Long Duration Energy Storage

The ACES capacity expansion model was used to simulate the economic and operational performance of long duration energy storage under realistic policy and market conditions.

Part IV: Results Analysis & Strategic Insights

Modeled scenarios were compared, identifying system impacts, and developing recommendations for policymakers, utilities, and investors.

Key Findings

This study combined a detailed screening of six long-duration energy storage technologies with capacity expansion modelling to evaluate their role in Prince Edward Island’s electricity system. The results and findings are as follows:

Technology Screening Insights

• Most Viable Options: From the PNNL database used, pumped hydro, adiabatic compressed air, and hydrogen storage were excluded due to the island’s geography and geology. The remaining candidates were lithium-iron phosphate batteries, nickel manganese cobalt batteries, vanadium redox flow batteries, lead acid batteries, zinc-based batteries, and solid-state sensible heat storage.
• Performance Leaders: Both lithium batteries took the lead as the most mature technologies, demonstrating the highest round-trip efficiency (85%), lowest operational expenditure, and strong energy density, making them well suited for near term deployment.
• Specialized Strengths: Vanadium redox flow batteries offer extremely low self-discharge for seasonal shifting (1.5% per month); zinc-bromine batteries have high volumetric density (315 Wh/l); solid state sensible heat storage provides the longest lifespan (34 years) and lowest energy capital expenditure, though with high power conversion costs and low round trip efficiency.
• Economic Considerations: A levelized cost of storage analysis showed lithium iron phosphate battery storage costing the cheapest at 10 hours duration, while solid state sensible heat storage was the cheapest at 24 hours duration due to low energy scaling costs.

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